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Retention of Hydraulic Fracturing Water in Shale: The Influence of Anionic Surfactant

Figure 5. The Energy-Dispersive X-Ray (EDX) spectra of (a) BG-2 and (b) KH-2 shales with a corresponding miniature FE-SEM images.

The readings were then plotted versus time to unravel the adsorption behavior under the effect of water retention. The investigation was carried out in “BG-2 and KH-2” shales before and after treatment with 1wt.% of IOS solution. The U.S Bureau of Mines (USBM) adsorption procedures were followed [34].

Results and Discussion

Mineralogy of Shales

The mineralogy results from X-ray Powder Diffraction (XRD) of the two shales “BG-2 and KH-2” used in this study are presented in Table 3. It can be seen that BG-2 shale contains a higher amount of clay and a lower amount of non-clay minerals as compared to KH-2. The difference in mineralogy in both shales will help better explain the water retention results.

Table 3. Quantitative mineralogy of BG-2 and KH-2 shales from XRD measurement.

Table 3. Quantitative mineralogy of BG-2 and KH-2 shales from XRD measurement.

The FE-SEM images of the two shales are shown in Figure 4. The platy/flaky structure of grains indicates the presence of clay. It can be seen that BG-2 (a) shale has more clay as compared to the KH-2 shale (b), which supports the XRD results.

Figure 4. FE-SEM images for (a) BG-2 and (b) KH-2 shales.

Figure 4. FE-SEM images for (a) BG-2 and (b) KH-2 shales.

The Energy-Dispersive X-Ray (EDX) spectra for BG-2 (a) and KH-2 (b) shales is shown in Figure 5 with a corresponding miniature image of Figure 4 embedded in the graph for ease of comparison.

Figure 5. The Energy-Dispersive X-Ray (EDX) spectra of (a) BG-2 and (b) KH-2 shales with a corresponding miniature FE-SEM images.

Figure 5. The Energy-Dispersive X-Ray (EDX) spectra of (a) BG-2 and (b) KH-2 shales with a corresponding miniature FE-SEM images.

The BG-2 shale spectrum shows high values of counts per second per electron-volt (cps/eV) at around 1.5 and 1.7 KeV identify Al and Si minerals respectively, thus indicating the presence of iron-rich platy crystals of clays such as kaolinite (Si, Al) and/or illite (Al, Si, K, Fe). While comparing the elements of KH-2 with BG-2, it is found that KH-2 shale is richer in carbon (C) and silicon (Si). However, it is lower in aluminum (Al), potassium (K), and iron (Fe). Furthermore, it contains a trace of calcium as opposed to magnesium (Mg) that was found in BG-2. Thus, the KH-2 shale is richer in silica and organic matters and has a lower clay content.

TOC

Figure 6 shows that KH-2 has a TOC of 12.1%, while BG-2 has only 2.1%. TOC is associated with the presence of organic matter in the shale. From the perspective of wettability, the organic matter contributes towards the hydrophobicity of shale [34]. As such, KH-2 is presumably more hydrophobic than BG-2.

Figure 6. The total organic carbon (TOC) percentage in BG-2 and KH-2 shales.

Fourier-Transform Infrared Spectroscopy (FTIR)

Figure 7 presents the FTIR spectra of BG-2 and KH-2 shales. The broadband existing between 3404 and 3627 cm−1 probably corresponds to O-H stretching of hydroxyl groups which could be attributed to the existence of clay minerals.

Figure 7. Fourier-Transform Infrared Spectroscopy (FTIR) Spectrum of BG-2 and KH-2 shales.

Figure 7. Fourier-Transform Infrared Spectroscopy (FTIR) Spectrum of BG-2 and KH-2 shales.

The presence of clay minerals and quartz is also inferred from the stretching of Si–O–Si band at about 1021 cm−1 [51]. The intensity of these bands in BG-2 is greater than KH-2 inferring that BG-2 is richer in clay than KH-2, which confirms XRD results in Table 3. The presence of organic matter is evidenced by the peaks at 1635 cm−1 and 676 cm−1. These peaks are attributed to C=O vibration of carboxylates and deformation of CH group; respectively. These two functional groups come from organic matter [51,52,53].

Wettability

Figure 8 display the wettability results by contact angle method of BG-2 (a) and KH-2 (b) shales with pure water and IOS solution. The presented contact angles are the average of the contact angles taken throughout three minutes to ensure the stability of the recorded contact angles. The lower contact angle of a solution on a surface indicates that it is more wetting than pure water. In BG-2 shale, the contact angle recorded with IOS solution was nearly 3.5°, which is lower than the contact angle with pure water that was about 22°. Therefore, it can be deduced that IOS solution was more wetting than pure water for BG-2 shale. Similar but less obvious behavior was seen in KH-2 shale, where a contact angle of approximately 19.5° was measured with IOS solution compared to 37° contact angle obtained with pure water. Figure 8. Measured contact angles at (a) BG-2 shale surface with pure water and 1 wt.% IOS solution (b) KH-2 shale surface with pure water and 1wt.% IOS solution.

Figure 8. Measured contact angles at (a) BG-2 shale surface with pure water and 1 wt.% IOS solution (b) KH-2 shale surface with pure water and 1wt.% IOS solution.

Water Uptake

Figure 9 displays the water uptake volume in BG-2 and KH-2 shales before and after treatment with 1 wt.% of IOS solution. The amount of retained water in both shales increased significantly after treating the shales with the IOS solution. When BG-2 shale was immersed in pure distilled water, the volume of water uptake was noted to be 11.2 mL. It increased to 21 mL (an 87% increase) when immersed in a 1 wt.% IOS solution. Similar but less significant behavior was seen in KH-2 shale in which the amount of water uptake increased drastically from 8 mL in pure distilled water to 18.5 mL (a 131% increase) in 1 wt.% IOS solution.

It is noteworthy to mention that the upsurge in water uptakes is possibly due to wettability alteration of shales by IOS towards more water wet. In a previous study [34] in two shales from the same formations, it was noticed that IOS changed the wettability of shales into more water- wet. These findings correlate well with the wettability results in Figure 8. IOS was more wetting than pure water in both shales hence imbibing more than pure water.

Figure 9. Water uptakes volume in BG-2 and KH-2 shales.

End Cycle Pressure vs. Time

The USBM’s gas adsorption method was adopted in this study to study the adsorption behavior of shales. According to previous studies, water retention in shale was found to impair gas flow in shale. The decline in the quantity of adsorbed CH4 was used to explain the water retention behaviors in both shales. More pressure drop during CH4 adsorption process presumably indicates higher gas adsorption and vice versa. CH4 adsorption in the two shales “BG-2 and KH-2” was performed before and after treatment with IOS surfactant and the pressure drop versus time was utilized to explain the water uptakes in both shales.

A crushed shale specimen (100 g) was placed in the adsorption column which was then closed/sealed and tested for gas leakage. The column was pressurized to 20 bar with CH4, and then the connection to the gas source was closed to isolate the chamber. The pressure was noted at the end of the 2 h adsorption cycle, and the valve connecting to the CH4 source was re-opened momentarily, and the column was re-pressurized to 20 bar again. Ten of such cycles were repeated for each shale.

Figure 10 displays the pressure reading at the end of each cycle vs. time for BG-2 and KH-2 shales. The black curve is for pure distilled water treated while the red curve is for the IOS treated shale. In the case of pure distilled water treated shale, the pressure continued decreasing till the end of the 5th adsorption cycles (10 h) indicating the continued CH4 adsorption. The pressure at the end of the 6th cycle was similar to the 5th cycle suggesting that the rate of adsorption is leveling off. The lowest pressure observed during the test was 14 bar (a 30% change in pressure), and it occurred after about 12 h.

The pressure change at the end of each subsequent cycle became gradually smaller until the last two cycles in which there was no change in pressure indicating that CH4 adsorption is completed. When BG-2 shale was treated with IOS, the end of cycle pressure profile drastically changed. The lowest pressure observed during the test was 18 bar (only 10% change in pressure), and it occurred after just the 1st cycle (2 h). The next two cycles saw a slow reduction of the end of cycle pressure, but there was no change in pressure reduction after the 5th cycle. When comparing the behavior of the two curves, it becomes evident that IOS treatment has reduced the adsorption capacity of the shale.

For the pure distilled water treated KH-2 shale, the cycle end pressure continued decreasing till the end of the 4th adsorption cycles indicating the continued CH4 adsorption. The pressures at the end of the 5th–7th cycles were similar to the 4th cycle suggesting that the rate of adsorption was leveling off.

 

Figure 10. Column pressure at the end of adsorption cycle vs. time for (a) BG-2 and (b) KH-2 shales.

The lowest pressure observed during the test was 10 bar (a 50% change in pressure), and it occurred after about 6 h (3rd cycle). The pressure changes at the end of each subsequent cycle became gradually smaller until the last three cycles in which there was no change in pressure indicating that complete CH4 adsorption was achieved. In the case of KH-2 that was treated with IOS, the end of cycle pressure profile significantly changed. The lowest pressure observed during the test was 14 bar (a 30% change in pressure), and it occurred after only the third cycle. The pressures at the end of 4th cycles were similar to the 3rd cycle suggesting no change in the rate of adsorption. The next four cycles saw a gradual reduction of the end of cycle pressure, but there was no change in pressure reduction after the 7th cycle. While comparing the behavior of the two curves, it becomes evident that IOS treatment has reduced the adsorption capacity of KH-2 shale.

Figure 11 shows a comparison of the two shales “BG-2 and KH-2” after treatment with pure distilled water only. The pressure at the end of each adsorption cycle was plotted vs. time. The solid curve is for KH-2 water-treated shale, while the dotted curve is for BG-2 water-treated shale. In the first adsorption cycle, a similar cycle-end pressure was noted in both shales. Later, KH-2 shale showed a more drastic change in cycle-end pressure till the end of the 3rd cycle (a 50% reduction in pressure). A less pronounced decrease in pressure was seen in BG-2 shale, where only a 30% reduction in pressure was noted at the end of the 5th cycle. When comparing the cycle-end pressure of the two shales, it becomes clear that the amount adsorbed CH4 was more in KH-2 shale. It is most likely attributed to the fact that KH-2 is richer than BG-2 in organic matter.

Figure 11. The end cycle adsorption pressure for BG-2 and KH-2 shales treated with pure water.

Figure 11. The end cycle adsorption pressure for BG-2 and KH-2 shales treated with pure water.

The adsorption behavior of the two shales “BG-2 and KH-2” after treatment with IOS is shown in Figure 12, where the end-cycle pressure is plotted vs. time. A reduction in pressure was noted in KH-2 shale (solid curve) up to the end of the 3rd cycle (a 30% reduction in pressure). However, it was not as significant as with the purely distilled water case cycle (was a 50% reduction in pressure). Less significant reduction in end-cycle pressure was seen in BG-2 shale, where only a 10% reduction in pressure was noted at the end of the 2nd cycle. When comparing the end cycle pressure reading in both shales, it is found that KH-2 showed higher CH4 adsorption than BG-2, as was the case with pure water treatment.

Figure 12. The end cycle adsorption pressure for BG-2 and KH-2 shales treated with IOS

Figure 12. The end cycle adsorption pressure for BG-2 and KH-2 shales treated with IOS

It is evident from Figure 11 and Figure 12 that IOS treatment has reduced the CH4 adsorption in both shales as compared to pure water treatment. It should be noted that the IOS had increased the water retention in both shales as compared to pure water treatment. Presumably, the higher water retention in both shales occupied some of the available adsorption sites, thus resulting in lower gas adsorption.

Conclusions

In this study, the influence of anionic surfactant on water retention in shales was investigated. Two well-characterized Malaysian shales “BG-2 and KH-2” were treated with 1 wt.% IOS solution, and the changes in water uptake were noted. The water retention phenomenon was inferred from the results of the water imbibition and gas adsorption tests. When BG-2 and KH-2 shales were treated with 1 wt.% IOS solution, their water retention and CH4 adsorption characteristics changed compared to the case when they were immersed in pure water. The water uptakes dramatically increased by 131% in KH-2 and 87% in BG-2, while CH4 adsorption was reduced by 50% in KH-2 and 30% in BG-2. It is presumed that the higher water retention in both shales occupied some of the available adsorption sites, thus resulting in lower gas adsorption.

The mineralogical analysis of the two shales showed that higher water retention and consequent lower gas adsorption was observed in BG-2 shale which had a higher clay content of 57% and low TOC of 2.1% as compared to the KH-2. The difference in the amount of retained water in both shales was found to correlate with their TOC and mineralogy. The higher affinity of BG-2 to retain a significant amount of water is possibly attributed to its high clay content and poor organic material. The relatively lower water uptake in KH-2 is presumably attributed to its high TOC of 12.1% and low clay content of 26%. As opposed to clay, organic matter is hydrophobic and thus hindering water imbibition. These results also suggest that the addition of anionic surfactant into the fracking fluid cocktail for hydraulic fracturing of shales could increase the water retention issue.

Author Contributions

Conceptualization, H.A.; methodology, H.A. and S.M.M.; software, S.A.-H.; validation, H.A., S.M.M. and M.H.H.; formal analysis, H.A.; investigation, H.A.; resources, S.M.M.; data curation, H.A and M.H.H.; writing—original draft preparation, H.A.; writing—review and editing, S.A.-H.; S.M.M. and H.A.; visualization, H.A. and S.M.M.; supervision, S.M.M. project administration, E.P.; funding acquisition, E.P.

Funding

This research was funded by Shale Gas Research Group (SGRG) and PRF-Research Grant (Cost Center 0153AB-A33).

Acknowledgments

We acknowledge the Shale Gas Research Group (SGRG) in UTP and Shale PRF project (cost center # 0153AB-A33) for the financial support. We also thank SHELL for providing the surfactant.

Conflicts of Interest

The authors declare no conflict of interest.

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© 2018 by the authors. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (http://creativecommons.org/licenses/by/4.0/).

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.
http://www.allaboutshale.com

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